Well Servicing and Well Fluids
To produce oil or gas from a reservoir, a well is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. Typically, a wellbore of a well must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation.
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.
Common Well Treatments and Well fluids
Well services can include various types of treatments that are commonly performed in a wellbore or subterranean formation.
For example, a treatment for fluid-loss control can be used during any of drilling, completion, and intervention operations. During completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil and gas from a well.
Well services can include various types of treatments that are commonly performed in a wellbore or subterranean formation. For example, stimulation is a type of treatment performed to enhance or restore the productivity of oil or gas from a well. Even small improvements in fluid flow can yield dramatic production results.
Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Fracturing treatments are often applied in treatment zones having poor natural permeability. Matrix treatments are often applied in treatment zones having good natural permeability to counteract damage in the near-wellbore area.
Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, acidizing, and controlling excessive water production. Still other types of completion or intervention treatments include, but are not limited to, damage removal, formation isolation, wellbore cleanout, scale removal, and scale control.
Hydraulic Fracturing
Hydraulic fracturing is a common stimulation treatment. The purpose of a hydraulic fracturing treatment is to provide an improved flow path for oil or gas to flow from the hydrocarbon-bearing formation to the wellbore. In addition, a fracturing treatment can facilitate the flow of injected treatment fluids from the well into the formation. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance one or more fractures in the subterranean formation. Creating a fracture means making a new fracture in the formation Enhancing a fracture means enlarging a pre-existing fracture in the formation.
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Preferably, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
Polymers for Increasing Viscosity of Well Fluid
A well fluid can be adapted to be a carrier fluid for particulates.
For example, a proppant used in fracturing or a gravel used in gravel packing may have a much different density than the carrier fluid. For example, sand has a specific gravity of about 2.7, whereas water has a specific gravity of 1.0 at Standard Laboratory Conditions of temperature and pressure. A proppant or gravel having a different density than water will tend to separate from water very rapidly.
Increasing the viscosity of a well fluid can help prevent a particulate having a different specific gravity than a surrounding phase of the fluid from quickly separating out of the fluid.
A viscosity-increasing agent can be used to increase the ability of a fluid to suspend and carry a particulate material in a well fluid. A viscosity-increasing agent can be used for other purposes, such as matrix diversion, conformance control, or friction reduction.
A viscosity-increasing agent is sometimes referred to in the art as a viscosifying agent, viscosifier, thickener, gelling agent, or suspending agent. In general, any of these refers to an agent that includes at least the characteristic of increasing the viscosity of a fluid in which it is dispersed or dissolved. There are several kinds of viscosity-increasing agents or techniques for increasing the viscosity of a fluid.
Certain kinds of polymers can be used to increase the viscosity of a fluid. In general, the purpose of using a polymer is to increase the ability of the fluid to suspend and carry a particulate material. Polymers for increasing the viscosity of a fluid are preferably soluble in the external phase of a fluid. Polymers for increasing the viscosity of a fluid can be naturally occurring polymers such as polysaccharides, derivatives of naturally occurring polymers, or synthetic polymers.
Well fluids used in high volumes, such as fracturing fluids, are usually water-based. Efficient and inexpensive viscosity-increasing agents for water include certain classes of water-soluble polymers.
The water-soluble polymer can have an average molecular weight in the range of from about 50,000 to 20,000,000, most preferably from about 100,000 to about 4,000,000. For example, guar polymer is believed to have a molecular weight in the range of about 2 to about 4 million.
Typical water-soluble polymers used in well treatments include water-soluble polysaccharides and water-soluble synthetic polymers (e.g., polyacrylamide). The most common water-soluble polysaccharides employed in well treatments are guar and its derivatives.
Synthetic polymers and copolymers can be used. Examples of such synthetic polymers include, but are not limited to, polyacrylate, polymethacrylate, polyacrylamide, polyvinyl alcohol, and polyvinylpyrrolidone. Commonly used synthetic polymer acid-viscosity-increasing agents are polymers or copolymers consisting of various ratios of acrylic, acrylamide, acrylamidomethylpropane sulfonic acid, quaternized dimethylaminoethylacrylate, quaternized dimethylaminoethylmethacrylate, and combinations thereof.
Crosslinking of Polymer to Increase Viscosity
The viscosity of a fluid at a given concentration of viscosity-increasing agent can be greatly increased by crosslinking the viscosity-increasing agent. A crosslinking agent, sometimes referred to as a crosslinker, can be used for this purpose. A crosslinker interacts with at least two polymer molecules to form a “crosslink” between them.
If crosslinked to a sufficient extent, a polymer may form a gel with water. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular crosslinker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art.
For example, one of the most common viscosity-increasing agents used in the oil and gas industry is guar. A mixture of guar dissolved in water forms a base gel, and a suitable crosslinking agent can be added to form a much more viscous fluid, which is then called a crosslinked fluid. The viscosity of base gels of guar is typically about 20 mPa·s (20 cP) to about 50 mPa·s (50 cP). When a base gel is crosslinked, the viscosity is increased by 2 to 100 times depending on the temperature, the type of viscosity testing equipment and method, and the type of crosslinker used.
The degree of crosslinking depends on the type of viscosity-increasing polymer used, the type of crosslinker, concentrations, temperature of the fluid, etc. Shear is usually required to mix the base gel and the crosslinking agent. Thus, the actual number of crosslinks that are possible and that actually form also depends on the shear level of the system. The exact number of crosslink sites is not well known, but it could be as few as one to about ten per polymer molecule. The number of crosslinks is believed to significantly alter fluid viscosity.
For a polymeric viscosity-increasing agent, any crosslinking agent that is suitable for crosslinking the chosen monomers or polymers may be used.
Crosslinking agents typically comprise at least one metal ion that is capable of crosslinking the viscosity-increasing agent molecules.
Some crosslinking agents form substantially permanent crosslinks with viscosity-increasing polymer molecules. Such crosslinking agents include, for example, crosslinking agents of at least one metal ion that is capable of crosslinking gelling agent polymer molecules. Examples of such crosslinking agents include, but are not limited to, zirconium compounds (such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium maleate, zirconium citrate, zirconium oxychloride, and zirconium diisopropylamine lactate); titanium compounds (such as, for example, titanium lactate, titanium maleate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate); aluminum compounds (such as, for example, aluminum acetate, aluminum lactate, or aluminum citrate); antimony compounds; chromium compounds; iron compounds (such as, for example, iron chloride); copper compounds; zinc compounds; sodium aluminate; or a combination thereof.
Crosslinking agents can include a crosslinking agent composition that may produce delayed crosslinking of an aqueous solution of a crosslinkable organic polymer, as described in U.S. Pat. No. 4,797,216, the entire disclosure of which is incorporated herein by reference. Crosslinking agents can include a crosslinking agent composition that may include a zirconium compound having a valence of +4, an alpha-hydroxy acid, and an amine compound as described in U.S. Pat. No. 4,460,751, the entire disclosure of which is incorporated herein by reference.
Sometimes, however, crosslinking is undesirable, as it may cause the polymeric material to be more difficult to break and it may leave an undesirable residue in the formation.
Other Uses of Polymers in Well Fluids, for Example, as Friction Reducer
There are other uses for a polymers in a well fluid. For example, a polymer may be used as a friction reducer.
During the drilling, completion, or stimulation of subterranean wells, well fluids are often pumped through tubular structures (e.g., pipes, coiled tubing, etc.). A considerable amount of energy may be lost due to turbulence in the well fluid. Because of these energy losses, additional horsepower may be necessary to achieve the desired treatment. To reduce these energy losses, certain polymers (referred to herein as “friction-reducing polymers”) have been included in these well fluids.
Suitable friction reducing polymers should reduce energy losses due to turbulence within the well fluid. Those of ordinary skill in the art will appreciate that the friction reducing polymer(s) included in the well fluid should have a molecular weight sufficient to provide a desired level of friction reduction. In general, polymers having higher molecular weights may be needed to provide a desirable level of friction reduction.
A wide variety of friction reducing polymers are available. In certain embodiments, the friction-reducing polymer may be a synthetic polymer. Additionally, for example, the friction-reducing polymer may be an anionic polymer or a cationic polymer.
By way of example, suitable synthetic polymers may include any of a variety of monomeric units, including acrylamide, acrylic acid, 2-acrylamido-2-methylpropane sulfonic acid, N,N-dimethylacrylamide, vinyl sulfonic acid, N-vinyl acetamide, N-vinyl formamide, itaconic acid, methacrylic acid, acrylic acid esters, methacrylic acid esters, quaternized aminoalkyl acrylate, such as a copolymer of acrylamide and dimethylaminoethyl acrylate quaternized with benzyl chloride, and mixtures thereof.
Examples of suitable friction reducing polymers are described in: U.S. Pat. No. 6,784,141 issued Aug. 31, 2004 having for named inventors Karen L. King, David E. Mcmechan, and Jiten Chatterji entitled “Methods, Aqueous Well Treating Fluids and Friction Reducers Therefor”; U.S. Pat. No. 7,004,254 issued on Feb. 28, 2006 having for named inventors Jiten Chatterji, Karen L. King, and David E. McMechan entitled “Subterranean Treatment Fluids, Friction Reducing Copolymers, and Associated Methods”; U.S. Pat. No. 7,232,793 issued Jun. 19, 2007 having for named inventors Karen L. King, David E. McMechan; and Jiten Chatterji entitled “Water-Based Polymers for Use as Friction Reducers in Aqueous Treatment Fluids”; U.S. Pat. No. 7,271,134 issued Sep. 18, 2007 having for named inventors Karen L. King, David E. McMechan; and Jiten Chatterji entitled “Water-Based Polymers for Use as Friction Reducers in Aqueous Treatment Fluids”; each of which is incorporated herein by reference in the entirety.
One example of a suitable anionic friction-reducing polymer is a polymer including at least acrylamide and acrylic acid monomeric units. The acrylamide and acrylic acid may be present in the polymer in any suitable concentration. An example of a suitable anionic friction reducing polymer may include at least acrylamide monomer in an amount in the range of from about 5% to about 95% and acrylic acid monomer in an amount in the range of from about 5% to about 95%. Another example of a suitable anionic friction-reducing polymer may include acrylamide in an amount in the range of from about 60% to about 90% by weight and acrylic acid in an amount in the range of from about 10% to about 40% by weight. Another example of a suitable anionic friction-reducing polymer may include acrylamide in an amount in the range of from about 80% to about 90% by weight and acrylic acid in an amount in the range of from about 10% to about 20% by weight. Yet another example of a suitable anionic friction-reducing polymer may include acrylamide in an amount of about 85% by weight and acrylic acid in an amount of about 15% by weight. As previously mentioned, one or more additional monomers may be included in the anionic friction reducing polymer including acrylamide and acrylic acid monomeric units. By way of example, the additional monomer(s) may be present in the anionic friction-reducing polymer in an amount up to about 20% by weight of the polymer.
Suitable friction-reducing polymers may be in an acid form or in a salt form. As will be appreciated, a variety of salts may be prepared, for example, by neutralizing the acid form of the acrylic acid monomer or the 2-acrylamido-2-methylpropane sulfonic acid monomer. In addition, the acid form of the polymer may be neutralized by ions present in the well fluid. As used herein, the term “polymer” is intended to refer to the acid form of the friction-reducing polymer as well as its various salts.
Slick-Water Fracturing of Shale Formations
An example of a well treatment that may utilize a friction-reducing polymer is commonly referred to as “high-rate water fracturing” or “slick-water fracturing,” which is commonly used for fracturing of ultra-low permeable formations such as shale formations.
Ultra-low permeable formations tend to have a naturally occurring network of multiple interconnected micro-sized fractures. The fracture complexity is sometimes referred to in the art as a fracture network. Ultra-low permeable formations can be fractured to create or increase such multiple interconnected micro-sized fractures. This approach can be used to help produce gas from such an ultra-low permeable formation. According to current technology, a shale formation suitable for economic recovery as a gas reservoir is characterized by having a hydrocarbon content greater than 2% by volume gas filled porosity.
Ultra-low permeable formations are usually fractured with water-based fluids having little viscosity and that are used to suspend relatively low concentrations of proppant. The size of the proppant is sized to be appropriate for the fracture complexity of such a formation, which is much smaller than used for fracturing higher permeability formations such as sandstone or even tight gas reservoirs. The overall purpose is to increase or enhance the fracture complexity of such a formation to allow the gas to be produced. Although the fractures of the fracture network are very small compared to fractures formed in higher permeability formations, they should still be propped open.
Stimulated rock volume is a term used in the art regarding the fracturing of shale or other ultra-low permeability reservoirs. “Ultra-low permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concept of a single fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3-D volume (Stimulated Reservoir Volume or SRV) of the microseismic event cloud.” M. J. Mayerhofer, E. P. Lolon, N. R. Warpinski, C. L. Cipolla, and D. Walser, Pinnacle Technologies, and C. M. Rightmire, Forrest A. Garb and Associates; Society of Petroleum Engineers, “SPE Shale Gas Production Conference, 16-18 Nov. 2008, Fort Worth, Tex., USA,” “What is Stimulated Rock Volume?” SPE 119890.
The fracturing fluids for use in fracturing ultra-low permeability formations are water-based. One of the reasons for this is the large volumes required, and water is relatively low cost compared to oil-based fluids. Other reasons can include concern for damaging the reservoir and environmental concerns.
Preferably, a friction-reducing polymer can be included in a well fluid in an amount equal to or less than 0.2% by weight of the water present in the well fluid. Preferably, any friction-reducing polymers are included in a concentration sufficient to reduce friction but at a lower concentration than would develop the characteristic of a gel. By way of example, the well fluid including the friction-reducing polymer would not exhibit an apparent yield point. While the addition of a friction-reducing polymer may minimally increase the viscosity of the well fluids, the polymers are not included in the well fluids in an amount sufficient to substantially increase the viscosity. For example, if proppant is included in the wells fluid, velocity rather than fluid viscosity generally may be relied on for proppant transport. In some embodiments, the friction-reducing polymer can be present in an amount in the range of from about 0.01% to about 0.15% by weight of the well fluid. In some embodiments, the friction-reducing polymer can be present in an amount in the range of from about 0.025% to about 0.1% by weight of the well fluid.
Generally, the treatment fluids in slick-water fracturing not relying on viscosity for proppant transport. Where particulates (e.g., proppant, etc.) are included in the fracturing fluids, the fluids rely on at least velocity to transport the particulates to the desired location in the formation. Preferably, a friction-reducing polymer is used in an amount that is sufficient to provide the desired friction reduction without appreciably viscosifying the fluid and usually without a crosslinker. As a result, the fracturing fluids used in these high-rate water-fracturing operations generally have a lower viscosity than conventional fracturing fluids for conventional formations. In some slick-water fracturing embodiments, the treatment fluids may have a viscosity up to about 10 mPa·s (10 cP). In some embodiments, the treatment fluids may have a viscosity in the range of from about 0.7 mPa·s (0.7 cP) to about 10 mPa·s (10 cP).
Sand Control and Gravel Packing
Gravel packing is commonly used as a sand-control method to prevent production of formation sand or other fines from a poorly consolidated subterranean formation. In this context, “fines” are tiny particles, typically having a diameter of 43 microns or smaller, that have a tendency to flow through the formation with the production of hydrocarbon. The fines have a tendency to plug small pore spaces in the formation and block the flow of oil. As all the hydrocarbon is flowing from a relatively large region around the wellbore toward a relatively small area around the wellbore, the fines have a tendency to become densely packed and screen out or plug the area immediately around the wellbore. Moreover, the fines are highly abrasive and can be damaging to pumping and oilfield other equipment and operations.
Placing a relatively larger particulate near the wellbore helps filter out the sand or fine particles and prevents them from flowing into the well with the produced fluids. The primary objective is to stabilize the formation while causing minimal impairment to well productivity.
The particulate used for this purpose is referred to as “gravel.” In the oil and gas field, and as used herein, the term “gravel” is refers to relatively large particles in the sand size classification, that is, particles ranging in diameter from about 0.1 mm up to about 2 mm. Generally, a particulate having the properties, including chemical stability, of a low-strength proppant is used in gravel packing. An example of a commonly used gravel packing material is sand having an appropriate particulate size range. For various purposes, the gravel particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like. For example, a tackifying agent can help with fines and resins can help to enhance conductivity (e.g., fluid flow) through the gravel pack.
In one common type of gravel packing, a mechanical screen is placed in the wellbore and the surrounding annulus is packed with a particulate of a larger specific size designed to prevent the passage of formation sand or other fines. It is also common, for example, to gravel pack after a fracturing procedure, and such a combined procedure is sometimes referred to as a “frac-packing.”
Like with placing a proppant in a subterranean formation during hydraulic fracturing, in gravel packing a viscosified fluid can be used to help transport and place the gravel in the well.
Fluid-Loss Control
Fluid loss refers to the undesirable leakage of a fluid phase of any type of well fluid into the permeable matrix of a zone, which zone may or may not be a treatment zone. Fluid-loss control refers to treatments designed to reduce such undesirable leakage. Providing effective fluid-loss control for well fluids during certain stages of well operations is usually highly desirable.
The usual approach to fluid-loss control is to substantially reduce the permeability of the matrix of the zone with a fluid-loss control material that blocks the permeability at or near the face of the rock matrix of the zone. For example, the fluid-loss control material may be a particulate that has a size selected to bridge and plug the pore throats of the matrix. All else being equal, the higher the concentration of the appropriately sized particulate, the faster bridging will occur. As the fluid phase carrying the fluid-loss control material leaks into the formation, the fluid-loss control material bridges the pore throats of the matrix of the formation and builds up on the surface of the borehole or fracture face or penetrates only a little into the matrix. The buildup of solid particulate or other fluid-loss control material on the walls of a wellbore or a fracture is referred to as a filtercake. Depending on the nature of a fluid phase and the filtercake, such a filtercake may help block the further loss of a fluid phase (referred to as a filtrate) into the subterranean formation. A fluid-loss control material is specifically designed to lower the volume of a filtrate that passes through a filter medium. Accordingly, a fluid-loss control material is sometimes referred to as a filtration control agent.
Fluid-loss control materials are sometimes used in drilling fluids or in treatments that have been developed to control fluid loss. A fluid-loss control pill is a treatment fluid that is designed or used to provide some degree of fluid-loss control. Through a combination of viscosity, solids bridging, and cake buildup on the porous rock, these pills oftentimes are able to substantially reduce the permeability of a zone of the subterranean formation to fluid loss. They also generally enhance filter-cake buildup on the face of the formation to inhibit fluid flow into the formation from the wellbore.
Fluid-loss control pills typically include an aqueous continuous phase and a high concentration of a viscosifying agent (usually crosslinked), and sometimes, bridging particles, such as graded sand, graded salt particulate, or sized calcium carbonate particulate.
Crosslinked gels can also be used for fluid-loss control. Crosslinking the gelling agent polymer helps create a gel structure that can suspend solids as well as provide fluid-loss control. Further, crosslinked fluid-loss control pills have demonstrated that they require relatively limited invasion of the formation face to be fully effective. To crosslink the viscosifying polymers, a suitable crosslinking agent that includes polyvalent metal ions is used. Boron, aluminum, titanium, and zirconium are common examples.
Acidizing
The purpose of acidizing in a well is to dissolve acid-soluble materials. For example, this can help remove residual fluid material or filtercake damage or to increase the permeability of a treatment zone. Conventionally, a treatment fluid including an aqueous acid solution is introduced into a subterranean formation to dissolve the acid-soluble materials. In this way, fluids can more easily flow from the formation into the well. In addition, an acid treatment can facilitate the flow of injected treatment fluids from the well into the formation. This procedure enhances production by increasing the effective well radius.
In acid fracturing, an acidizing fluid is pumped into a formation at a sufficient pressure to cause fracturing of the formation and to create differential (non-uniform) etching leading to higher fracture conductivity. Depending on the formation mineralogy, the acidizing fluid can etch the fracture faces, whereby flow channels are formed when the fractures close. The acidizing fluid can also enlarge the pore spaces in the fracture faces and in the formation.
In matrix acidizing, an acidizing fluid is injected from the well into the formation at a rate and pressure below the pressure sufficient to create a fracture in the formation.
Greater details, methodology, and exceptions can be found in “Production Enhancement with Acid Stimulation” 2nd edition by Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE 121464, SPE 121803, SPE 121008, IPTC 10693, and the references contained therein.
The use of the term “acidizing” herein refers to both matrix and fracturing types of acidizing treatments, and more specifically, refers to the general process of introducing an acid down hole to perform a desired function, e.g., to acidize a portion of a subterranean formation or any damage contained therein.
Conventional acidizing fluids can include one or more of a variety of acids, such as hydrochloric acid, acetic acid, formic acid, hydrofluoric acid, or any combination of such acids. In addition, many fluids used in the oil and gas industry include a water source that may incidentally contain certain amounts of acid, which may cause the fluid to be at least slightly acidic.
When an acidic fluid is used to stimulate a substantially acid-soluble formation below the fracturing pressure, the treatment is called matrix acidizing. Studies have shown that the dissolution pattern created by the flowing acid occurs by one of three mechanisms (a) compact dissolution, in which most of the acid is spent near the wellbore rock face; (b) wormholing, in which the dissolution advances more rapidly at the tips of a small number of wormholes than at the wellbore walls; and (c) uniform dissolution, in which many pores are enlarged. Compact dissolution occurs when acid spends on the face of the formation. In this case, the live acid penetration is commonly limited to within a few centimeters of the wellbore. Uniform dissolution occurs when the acid reacts under the laws of fluid flow through porous media. In this case, the live acid penetration will be, at most, equal to the volumetric penetration of the injected acid. (Uniform dissolution is also the preferred primary mechanism of conductive channel etching of the fracture faces in acid fracturing, as discussed above.) The objectives of the matrix acidizing process are met most efficiently when near wellbore permeability is enhanced to the greatest depth with the smallest volume of acid. This occurs in regime (b) above, when a wormholing pattern develops.
However, just as wormholing prevents the growth of large fractures, wormholing prevents the uniform treatment of long zones of a formation along a wellbore. Once wormholes have formed, at or near a point in the soluble formation where the acid first contacts the formation, subsequently-injected acid will tend to extend the existing wormholes rather than create new wormholes further along the formation. Temporary blockage of the first wormholes is needed so that new wormholes can be formed and the entire section of the formation treated. This is called “diversion,” as the treatment diverts later-injected acid away from the pathway followed by earlier-injected acid. In this case, the blockage must be temporary because all the wormholes are desired to serve as production pathways.
Increasing the viscosity or gelling of a fluid can help divert the treatment fluid from higher permeability to lower permeability portions of a zone. This can be useful for leak-off control in acid fracturing or matrix diversion in matrix acidizing.
Similar fluids and methods can be used for “leak-off control” in fracturing and for “diversion” in matrix acidizing. Such a method or acidic fluid may be termed a “leak-off control acid system” or a “self-diverting acid system” depending upon its use and purpose.
There are certain polymeric viscosity-increasing agents that develop viscosity after the acid starts to spent and the pH increases. This results in better diversion that can be considered as another advantage of the fluid. The acid diversion is very important in acid stimulation treatment to enhance oil production by creating better wormholes. It also increases the depth of penetration of acid into the reservoir.
Damage to Permeability
In well treatments using viscous well fluids, the material for increasing the viscosity of the fluid can damage the permeability of the proppant pack or the matrix of the subterranean formation. For example, a well fluid can include a polymeric material that is deposited in the fracture or within the matrix. By way of another example, the fluid may include surfactants that leave unbroken micelles in the fracture or change the wettability of the formation in the region of the fracture.
The term “damage” as used herein regarding a formation refers to undesirable deposits in a subterranean formation that may reduce its permeability. Scale, skin, gel residue, and hydrates are contemplated by this term. Also contemplated by this term are geological deposits, such as, but not limited to, carbonates located on the pore throats of a sandstone formation.
After application of a filtercake, it may be desirable to restore permeability into the formation. If the formation permeability of the desired producing zone is not restored, production levels from the formation can be significantly lower. Any filtercake or any solid or polymer filtration into the matrix of the zone resulting from a fluid-loss control treatment must be removed to restore the formation's permeability, preferably to at least its original level. This is often referred to as clean up.
Breaker for Viscosity of Fluid or Filtercake
After a well fluid is placed where desired in the well and for the desired time, the fluid usually must be removed from the wellbore or the formation. For example, in the case of hydraulic fracturing, the fluid should be removed leaving the proppant in the fracture and without damaging the conductivity of the proppant bed. To accomplish this removal, the viscosity of the treatment fluid must be reduced to a very low viscosity, preferably near the viscosity of water, for optimal removal from the propped fracture. Similarly, when a viscosified fluid is used for gravel packing, the viscosified fluid must be removed from the gravel pack.
Reducing the viscosity of a viscosified well fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of well fluids are called breakers. Other types of viscosified well fluids also need to be broken for removal from the wellbore or subterranean formation.
No particular mechanism is necessarily implied by the term. For example, a breaker can reduce the molecular weight of a water-soluble polymer by cutting the long polymer chain. As the length of the polymer chain is cut, the viscosity of the fluid is reduced. This process can occur independently of any crosslinking bonds existing between polymer chains.
In the case of a crosslinked viscosity-increasing agent, for example, one way to diminish the viscosity is by breaking the crosslinks.
Thus, removal of the well fluid is facilitated by using one or more breakers to reduce fluid viscosity.
Unfortunately, another complicating factor exists. Because of the large size of the polymer, a filtration process can occur upon the face of a formation or fracture in conventional formation. A filtercake of the polymer can be formed while the aqueous fluid, KCl, and breakers pass into the matrix of the formation. Careful examination of this filtercake, which may be formed from crosslinked or uncrosslinked guar or other polymer, reveals a semi-elastic, rubberlike membrane. Once the polymer concentrates, it is difficult to solubilize the polymer. For example, a non-filtercake fluid consists of approximately 99.5 percent water and 0.5 percent polymer. Accordingly, for example, when the fracture closes in a fracturing treatment, the permeability of the proppant bed or the formation face may be severely damaged by the polymer filtercake. Viscosified gravel pack fluids need breakers, too. A filtercake deposited for fluid-loss control may also need a breaker to help remove the filtercake.
Breakers must be selected to meet the needs of each situation. First, it is important to understand the general performance criteria of breakers. In reducing the viscosity of the well fluid to a near water-thin state, the breaker must maintain a critical balance. Premature reduction of viscosity during the pumping of a well fluid can jeopardize the treatment. Inadequate reduction of fluid viscosity after pumping can also reduce production if the required conductivity is not obtained.
A breaker should be selected based on its performance in the temperature, pH, time, and desired viscosity profile for each specific treatment.
In fracturing, for example, the ideal viscosity versus time profile would be if a fluid maintained 100% viscosity until the fracture closed on proppant and then immediately broke to a thin fluid. Some breaking inherently occurs during the 0.5 to 4 hours required to pump most fracturing treatments. One guideline for selecting an acceptable breaker design is that at least 50% of the fluid viscosity should be maintained at the end of the pumping time. This guideline may be adjusted according to job time, desired fracture length, and required fluid viscosity at reservoir temperature. A typical gravel pack break criteria is a minimum 4-hour break time.
Chemical breakers used to reduce viscosity of a well fluid viscosified with a viscosity-increasing agent or to help remove a filtercake formed with such a viscosity-increasing agent are generally grouped into three classes: oxidizers, enzymes, and acids.
For a polymeric viscosity-increasing agent, the breakers operate by cleaving the backbone of polymer by hydrolysis of acetyl group, cleavage of glycosidic bonds, oxidative/reductive cleavage, free radical breakage, or a combination of these processes.
Oxidizing Breakers
Oxidizers commonly used to reduce viscosity of natural polymers includes, for example, sodium persulfate, potassium persulfate, ammonium persulfate, lithium or sodium hypochlorites, chlorites, peroxide sources (sodium perborate, sodium percarbonate, calcium percarbonate, urea-hydrogen peroxide, hydrogen peroxide, etc.), bromates, periodates, permanganates, etc. In these types of breakers, oxidation-reduction chemical reactions occur as the polymer chain is broken.
Different oxidizers are selected based on their performance at different temperature and pH ranges. Consideration is also given to the rate of oxidation at a particular temperature and pH range. For example, the rate at which a persulfate molecule breaks into two radicals is temperature dependent. Below 120° F. (49° C.) this process occurs very slowly, and the reaction can be catalyzed to obtain acceptable break rates. A variety of catalysts, including various organic amines, can be used for persulfate breakers. The optimum pH for persulfate oxidation is around 10 at low temperature (less than 150° F. or 66° C.). Above approximately 200° F. (93° C.), persulfate decomposes very quickly and breaks the polymer very quickly (i.e., with little delay in the break). Therefore, persulfate is generally not recommended as a breaker above about 200° F. Similarly chlorites are used for high temperature breakage in the range of about 150° F. to about 350° F. with optimum pH range of 6 to 12. Some breakers can also be activated by catalysts such as cobalt acetate, EDTA, NTA, etc. to function at different temperature ranges. Hypochlorites are generally used for low temperature breakage of natural polymers.
Enzymatic Breakers
Enzymes are also used to break the natural polymers in oil field applications. They are generally used at low temperature 25° C. (77° F.) to 70° C. (158° F.) as at higher temperature they denature and become ineffective. At very low temperatures, enzymes are not as effective as the rate of breakage of polymer is very slow and they are generally not recommended. Different types of enzymes are used to break different types of bond in the polysaccharides. Some enzymes break only α-glycosidic linkage and some break β-glycosidic linkage in polysaccharides. Some enzymes break polymers by hydrolysis and some by oxidative pathways. Generally, Hemicellulase is used to break guar polymers and Xanthanase is used to break Xanthan polymers. A specific enzyme is needed to break a specific polymer/polysaccharide. Enzymes are referred to as Nature's catalysts because most biological processes involve an enzyme.
Acid Breakers
Acids also provide a break via hydrolysis. Acids, however, pose various difficulties for practical applications. Acids are not used as a polysaccharide polymer breaker very often because of cost, poor break rate control, chemical compatibility difficulties, and corrosion of metal goods in a well.
Breaking of Polyacrylamides More Difficult
Fluids viscosified with a polyacrylamide, whether used as a viscosity-increasing agent, as a crosslinker, or both, can be more difficult to break in a controlled manner than fluids viscosified with a single-chain polysaccharide such as a guar. This is especially the case at lower temperatures of less than 93° C. (200° F.).